Methods and systems for separating hydrocarbons

ABSTRACT

Methods and systems for separating hydrocarbons are disclosed. In one example, a method for separating hydrocarbons includes separating a feed gas stream that includes methane, ethane, and propane and heavier hydrocarbons into a residue gas stream including the methane and the ethane and a natural gas liquids (NGL) stream include the propane and heavier hydrocarbons, compressing the residue gas stream to produce a hot and compressed residue gas stream, and heating a portion of the NGL stream with the hot and compressed residue gas stream.

TECHNICAL FIELD

The technical field relates generally to hydrocarbon separation methods and systems. More particularly, the technical field relates to methods and systems for separating ethane, propane, propylene, and heavier hydrocarbon liquids from a hydrocarbon gas stream, for example from a natural gas stream or from gases from refinery or petroleum plants.

BACKGROUND

In addition to methane, natural gas includes some heavier hydrocarbons with impurities, for example carbon dioxide, nitrogen, helium, water, and non-hydrocarbon acid gases. After compression and separation of these impurities, natural gas is further processed to separate and recover natural gas liquids (NGL). In fact, natural gas may include up to about fifty percent by volume of heavier hydrocarbons recovered as NGL. These heavier hydrocarbons may be separated from methane to be recovered as natural gas liquids. These valuable natural gas liquids include ethane, propane, butane, and other heavier hydrocarbons. In addition to these NGL components, other gases, including hydrogen, ethylene, and propylene may be contained in gas streams obtained from refinery or from petrochemical plants.

Processes for separating hydrocarbon gas components are well known in the art. For example, the pre-purified natural gas may be treated by any of a number of well known methods including absorption, refrigerated absorption, adsorption, and condensation at cryogenic temperatures down to about −175° F. Separation of the lower hydrocarbons is achieved in one or more distillation towers. The columns are often referred to as de-methanizer or de-ethanizer columns. Processes employing a de-methanizer column separate methane and other volatile components from ethane and less volatile components in the purified natural gas liquids. The methane fraction is recovered as purified gas for pipeline delivery. The ethane and less volatile components, including propane, are recovered as natural gas liquid. In some applications, however, it is desirable to minimize the ethane content of the NGL. In those applications, ethane and more volatile components are separated from propane and less volatile components in a column generally called the de-ethanizer column. Thus, known separations systems may be designed to operate in two different modes: a first mode, known as an ethane recovery mode, where ethane is included in the recovered NGL; and a second mode, known as an ethane rejection mode, where ethane content of the NGL is minimized.

In a typical cryogenic turbo expansion recovery process for high propane recovery that is capable of operating in an ethane rejection mode, a feed stream under pressure is cooled by heat exchange with other streams of the process and/or external sources of refrigeration. As the gas is cooled, liquid may be condensed and collected in one or more separators as high pressure liquid containing some of the desired propane and heavier components. Depending upon the richness of the gas and the amount of liquid formed, the high pressure liquid may be expanded to a lower pressure and fractionated. The vaporization occurring during expansion causes a further cooling of the stream. The expanded stream, which includes a mixture of liquid and vapor, is fractionated in a distillation column (de-ethanizer). In the de-ethanizer, the expansion cooled stream is distilled to separate residual methane, ethane, nitrogen, and other volatile components as overhead vapor product from the propane components and heavier hydrocarbons obtained as bottom liquid product.

A portion of the bottom liquid product is recycled back to the column using a reboiler. In some conventional systems, the required reboiler energy input is provided by the feed gas when the system is operating in an ethane recovery mode. This configuration has the advantage that the reboiler actually cools down the gas further. However, when the system is operating in ethane rejection mode, the temperature at which the reboiler operates needs to be elevated relative to the temperature of the feed gas. To provide this additional reboiler energy input, in some conventional systems, a hot oil system has been typically provided. Accordingly, if a separations system is required to run in both ethane recovery and ethane rejection mode, it may require a hot oil system to provide the additional heat duty in ethane rejection mode. This hot oil system adds extra cost to the operation of the separations system, both in terms of the capital cost required to provide the hot oil system, and the operating cost required to maintain the hot oil system at the appropriate temperature.

Accordingly, it is desirable to provide hydrocarbon separation methods and systems for the recovery of NGL that reduce capital and operating costs as compared to conventional methods and systems. Furthermore, it is desirable to provide hydrocarbon separation methods and systems for the recovery of NGL that are capable of operating in both ethane recover and ethane rejection modes that either reduce or do not require additional heat inputs to the system for the distillation column reboiler when operating in the ethane rejection mode. Furthermore, other desirable features and characteristics of the presently disclosed embodiments will become apparent from the subsequent detailed description and the appended claims, taken in conjunction with the accompanying drawings and this background.

BRIEF SUMMARY

Methods and systems for separating hydrocarbons are disclosed. In one exemplary embodiment, a method for separating hydrocarbons includes separating a feed gas stream that includes methane, ethane, propane, and heavier hydrocarbons into a residue gas stream including the methane and the ethane and a natural gas liquids (NGL) stream include the propane and heavier hydrocarbons, compressing the residue gas stream to produce a hot and compressed residue gas stream, and heating a portion of the NGL stream with the hot and compressed residue gas stream.

In another exemplary embodiment, a method for separating hydrocarbons includes passing a feed gas stream to a distillation column, the feed gas stream including methane, ethane, propane, and heavier hydrocarbons and, in the distillation column, separating the methane and the ethane from the propane and heavier hydrocarbons, thereby producing a residue gas stream including the methane and the ethane at an upper section of the distillation column and a natural gas liquids (NGL) stream including the propane and heavier hydrocarbons at a lower section of the distillation column. The method further includes separating the NGL stream into a first portion and a second portion, withdrawing the first portion from the distillation column as a product NGL stream, heating the second portion in a reboiler of the distillation column, and returning the heated second portion from the reboiler to the distillation column. Still further, the method includes passing the residue gas stream to a compressor to produce a hot and compressed residue gas stream and directing heat from the hot and compressed residue gas stream to the reboiler to heat the second portion of the product NGL stream.

In yet another exemplary embodiment, a system for separating hydrocarbons includes a distillation column that is configured to a) receive a feed gas stream including methane, ethane, propane, and heavier hydrocarbons and b) separate the methane and the ethane from the propane and heavier hydrocarbons to produce a residue gas stream including the methane and the ethane at an upper section of the distillation column and a natural gas liquids (NGL) stream including the propane and heavier hydrocarbons at a lower section of the distillation column. The system further includes a reboiler associated with the distillation column that a) receives a portion of the NGL stream from the distillation column, b) heats the portion of the NGL stream to form a heated NGL stream, and c) returns the heated portion of the NGL stream to the distillation column. Still further, the system includes a compressor that compresses the residue gas stream to produce a hot and compressed residue gas stream and a heat exchange apparatus that directs heat from the hot and compressed residue gas stream to the reboiler to provide heat to the reboiler to accomplish the function (b) of heating the portion of the NGL stream.

BRIEF DESCRIPTION OF THE DRAWING

The various embodiments will hereinafter be described in conjunction with the following drawing FIGURE, wherein like numerals denote like elements, and wherein:

FIG. 1 is a schematic illustration of a system and a method for separating hydrocarbons in accordance with exemplary embodiments.

DETAILED DESCRIPTION

The following detailed description is merely exemplary in nature and is not intended to limit the various embodiments or the application and uses thereof. Furthermore, there is no intention to be bound by any theory presented in the preceding background or the following detailed description.

Various embodiments contemplated herein relate to methods and systems for hydrocarbon separation that reduce or eliminate the need for additional heat inputs to the system in connection with a distillation column reboiler when operating in an ethane rejection mode. The described embodiments utilize the heat generated by a residue gas compressor of the system, as will be described in greater detail below, to provide some or all of the reboiler heat required to operate the distillation column in ethane rejection mode. Depending on the overall configuration of the system and the composition of the feed gas, it may thus be possible to completely eliminate the need for a hot oil system providing heat to the reboiler, or at least the size and operating expense of the hot oil system will be reduced where it is not possible to completely eliminate the use of such hot oil system.

Various values of temperature, pressure, flow rates, number of stages, feed entry stage number etc. are recited in association with the specific examples described below; those conditions are approximate and merely illustrative, and are not meant to limit the described embodiments. Additionally, for purposes of this disclosure, when the terms “middle”, “top” or “lower” are used with respect to a column or absorber, these terms are to be understood as relative to each other, i.e. that withdrawal of a stream from the “top” of the column is at a higher position than the stream withdrawn from a “lower” portion of the column. When the term “middle” is used it implies that the “middle” section is somewhere between the “upper” and the “lower” section of the column. However, when the terms “upper”, “middle” and “lower” have been used with respect to a distillation column it should not be understood that such a column is strictly divided into thirds by these terms.

FIG. 1 is a schematic illustration of a system 10 employing a method for separating hydrocarbons in accordance with exemplary embodiments of the present disclosure. The system 10 illustrated in FIG. 1 may be used for obtaining either high ethane recovery or high propane recovery from a mixture of hydrocarbons, when operating in an ethane recovery or an ethane rejection mode, respectively. Referring to FIG. 1, a feed gas stream 14 enters the system 10 at a pressure that may be from about 500 Psia to about 1500 Psia, for example about 1100 Psia, and at a temperature of from about 75° F. to about 125° F., for example about 100° F. In one embodiment, the feed gas stream 14 may be a “dry feed gas,” meaning that it has been pretreated as necessary to remove any concentration of CO₂, sulfur compounds, mercury compounds, and water. As such, in an embodiment, the feed gas stream 14 includes methane, ethane, and heavier hydrocarbons. The terms “heavier hydrocarbons” or “heavier hydrocarbon compounds” are used herein to mean hydrocarbons having a molecular weight greater than ethane, including for example propane, butanes, etc. In some embodiments, feed gas stream 14 includes ethane in combination with the heavier hydrocarbons compounds in an amount of up to about 50% by weight. Further, in gas streams obtained from refinery or from petrochemical plants, ethylene and propylene may additionally be present. The composition of the feed gas stream 14 with regard to the above-described constituents may vary widely depending on the source of such stream. In another embodiment, some or all of the sulfur constituents of the feed gas stream 14 may remain in the feed gas stream after pre-treating, and such sulfur constituents may then be removed from the resulting NGL product stream after processing according to the present disclosure, as will be described in greater detail below.

In embodiments, the system 10 includes a valve apparatus 13 that is configured to split the feed gas stream 14 into gas streams 14 a and 14 b when the system 10 is operating in ethane recovery mode. For example, in ethane recovery mode, the valve apparatus 13 may divert about 10% to about 50% of feed gas stream 14 into gas stream 14 b. Gas stream 14 a is fed to an inlet heat exchanger 66, where it is cooled and in some cases partially condensed. The resulting cooled gas stream 16 a is obtained from the inlet exchanger 66 at a temperature that may be from about −40° F. to about 40° F., such as about 0° F. The gas stream 14 b is fed to a reboiler 68 that is associated with distillation column 84. In ethane recovery mode, in the reboiler 68, this stream 14 b exchanges heat with a side liquid draw 85 a from the distillation column 84. In the reboiler 68, stream 14 b is cooled down to a temperature that may be from about −15° F. to about 25° F., such as about 5° F., and the resulting cooled stream 16 b is then mixed with the stream 16 a, with the use of valve apparatus 15, from the inlet heat exchanger 66, to form combined gas stream 16. In an alternative embodiment, stream 16 b passes through heat exchanger 66, or a different heat exchanger, prior to passing through the valve apparatus 15.

In embodiments, the system 10, when operating in the ethane rejection mode, however, does not divert any of the feed gas stream 14 into gas stream 14 b. Rather, an entirety of the feed gas stream 14 proceeds to the inlet heat exchanger 66, and henceforth into gas stream 16. Regardless of the mode of operation, the gas stream 16, as a result of cooling in the inlet heat exchanger 66 (and the reboiler 68 when system 10 is operating in ethane recovery mode), is partially condensed, and may be at a pressure of about 700 Psia to about 1500 Psia, for example about 1100 Psia, and at a temperature of about −15° F. to about 25° F., such as about 5° F.

Gas stream 16 is then passed to an expander/separator 70 where it is separated into a liquid stream 20 and a vapor stream 18. The vapor stream 18 is split into two streams, 26 and 24. Stream 26 forms a minority portion of the total stream 18 (for example, from about 5% to about 40%). Stream 24, the majority vapor portion, is expanded via an expander/compressor 74 to a pressure that may be from about 10 Psi to about 50 Psi above the operating pressure of the distillation column 84, as will be described in greater detail below. The resulting stream 28 from the expander discharge is obtained at a temperature of from about −60° F. to about −150° F., for example about −85° F., and is partially condensed. Stream 28 is fed to the middle section of the distillation column 84, as shown in FIG. 1.

Liquid stream 20 from the expander/separator 70 is expanded to a pressure of about 300 Psia to about 400 Psia, such as about 350 Psia, through the use of a control valve 72. Due to the expansion process, the liquid stream 20 is cooled down. A stream 22 a from the control valve 72 discharge is obtained at temperature of from about −40° F. to about −50° F., such as about −45° F. This stream 22 a is then used to provide some of the cooling duty for inlet heat exchanger 66, and is then sent to the middle section of the distillation column 84 (generally below the stream 28, described above).

The remaining portion of the vapor from the expander/separator 70, i.e. stream 26, is fed to a subcooler heat exchanger 76, where it exchanges heat with a cold product residue gas stream 40 from the top of the distillation column 84, as will be described in greater detail below. Within subcooler heat exchanger 76, stream 26 is condensed (either partially or completely) to form stream 30. Stream 30, which may be at a temperature of from about −80° F. to about −190° F., such as about −85° F., and at a pressure of from about 1000 Psia to about 1150 Psia, such as about 1075 Psia, may be fed to the upper section of the distillation column 84 using a valve apparatus 31.

Stream 40, from the upper portion of the distillation column 84 (and generally above the inlet for stream 30), is obtained as a lean residue gas product. This product stream 40, when system 10 is operating in ethane recovery mode, mostly (i.e., greater than about 90%) includes methane and ethane, and may include a small amount (i.e., less than about 10%) of propane and heavier hydrocarbons. In contrast, the product stream 40, when the system 10 is operating in ethane rejection mode, mostly (i.e., greater than about 90%) includes methane, and may include a small amount (i.e., less than about 10%) of ethane and heavier hydrocarbons. The stream 40, regardless of whether the system 10 is operating in the ethane recovery or the ethane rejection mode, is then fed to the subcooler heat exchanger 76, where it exchanges heat with stream 26, as describe above. In the process, the residue gas stream 40 heats up and a heated stream 42 is obtained at a temperature of from about −30° F. to about −50° F., such as about −40° F., and at a pressure of from about 300 Psia to about 350 Psia, for example about 325 Psia. The heated stream 42 is then fed to the inlet exchanger 66, where it provides further refrigeration to the inlet stream 14 a.

A warmed residue gas stream 46 a from the inlet exchanger 66 is sent to the suction of the expander/compressor 74. The expander/compressor 74 compresses the warmed residue gas stream 46 a to a pressure of from about 200 Psia to about 500 Psia, for example about 450 Psia. A compressed gas stream 46 from expander/compressor 74 discharge is then fed to a residue gas compressor 75, which further compresses the gas to a pipeline pressure of from about 1000 Psia to about 1200 Psia, for example about 1100 Psia.

When the system 10 is operating in the ethane rejection mode, heat generated by the compression of gas stream 46 in the residue gas compressor 75 may be used to provide some or all of the heat that is required by the reboiler 68 to operate in the ethane rejection mode. As shown in FIG. 1, a hot and compressed residue gas stream 50 from the residue compressor 75 is passed to a heating apparatus 58. The heating apparatus 58 provides heat via line 51 to the reboiler 68, in one of several embodiments as will be described in greater detail below.

In one embodiment, the heating apparatus 58 is a hot oil system that is used to provide heat to the reboiler 68 when the system 10 is operating in the ethane rejection mode. In embodiments, the heat generated by the hot and compressed residue gas stream 50 is insufficient alone to provide the required heat for the reboiler 68. Thus, the hot and compressed residue gas stream 50 is used to provide a portion of the heat required for the reboiler 68. In this embodiment, the energy input required by the heating apparatus 58 (hot oil system) is reduced as compared to systems that rely solely on external energy inputs, and as a consequence the overall size of the heating apparatus 58 (hot oil system) may be reduced. Accordingly, capital costs are saved by the system 10 requiring a relatively smaller heating apparatus 58 (hot oil system), and operating costs are reduced as less external energy inputs are required to operate the heating apparatus 58 (hot oil system).

In another embodiment, the heat apparatus 58 is a glycol/water mixture heating apparatus. In general, the heating apparatus 58 may be any type of apparatus that uses an external energy input to provide heat to the system 10, and, as noted above, may be embodied, for example, as a hot oil system or a glycol/water mixture system, or any other suitable type of system.

In another embodiment, the heating apparatus is the reboiler 68 itself (or a heating device directly connected thereto with no external energy source), and the hot and compressed residue gas stream 50 is used as the sole heat source to provide the heating duty required for the reboiler 68. In this embodiment, the hot and compressed residue gas stream 50 is passed to the reboiler 68 and provides all of the heat required by the reboiler 68, and no separate hot oil system (or other heating system) is provided. In this embodiment, the capital costs of the system 10 are reduced in that the system includes one fewer component (namely the hot oil system) and the operating costs of the system 10 are reduce in that no external energy input is required to provide the heating duty for the reboiler 68.

A residue gas stream 53 from the heating apparatus 58 discharge may then either be fed to an air cooler 59 and cooled and fed to a pipeline 61, or the hot gas 53 may be fed to the pipeline 61 directly as residue gas. When the system 10 is operating in the ethane recovery mode, the compressed residue gas stream 50 bypasses the heating apparatus 58, and is passed to either the air cooler 59 or directly to the pipeline 61 as residue gas.

Greater detail is now provided regarding the operation of the distillation column 84. In some embodiments, the distillation column 84 operates at a pressure of about 180 Psia to about 400 Psia, for example about 325 Psia, and may be embodied as a conventional distillation column containing a plurality of mass transfer contacting devices, trays, or packing, or some combinations of the above. For example, it may be equipped with one or more liquid draw trays in the lower section of the column to provide heat to the column to strip volatile components off from the bottom liquid product stream 110. This is accomplished by the use of the reboiler 68, the operation of which has been described above for both the ethane recovery and the ethane rejection modes. That is, side liquid draw stream 85 a is withdrawn from the lower portion of the distillation column 84 and is fed to the side reboiler 68 where it exchanges heat with the inlet stream 14 b in the ethane recovery mode or the hot and compressed residue gas stream 50 (either directly or as part of a hot oil system (illustrated by line 51)) in the ethane rejection mode. As a result, stream 85 a picks up heat and a heated stream 85 b is sent back to the distillation column 84.

In the column 84, the lighter more volatile components are stripped off from the bottom liquid product, stream 110. This bottom liquid product contains predominantly (i.e., greater than about 90%) propane and heavier hydrocarbons when the system 10 is operating in the ethane rejection mode, and ethane and heavier hydrocarbons when the system 10 is operating in the ethane recovery mode. Stream 110 is then passed downstream for storage or further use as a NGL product stream.

Accordingly, the foregoing disclosure provides embodiments of methods and systems for separating hydrocarbons that reduce capital and operating costs as compared to systems known in the prior art. In particular, the methods and systems reduce the size of or eliminate the need for a hot oil system to provide heat to the distillation column reboiler when the system is operating in the ethane rejection mode, thereby reducing capital costs, by utilizing the heat generated by the residue gas compressor. The use of this heat further reduces or eliminates the need for external heat to be input to the system 10, thereby reducing operating costs of the system 10.

While at least one exemplary embodiment has been presented in the foregoing detailed description of the disclosure, it should be appreciated that a vast number of variations exist. It should also be appreciated that the exemplary embodiment or exemplary embodiments are only examples, and are not intended to limit the scope, applicability, or configuration of the disclosure in any way. Rather, the foregoing detailed description will provide those skilled in the art with a convenient road map for implementing an exemplary embodiment of the disclosure. It being understood that various changes may be made in the function and arrangement of elements described in an exemplary embodiment without departing from the scope of the disclosure as set forth in the appended claims. 

What is claimed is:
 1. A method for separating hydrocarbons comprising the steps of: separating a feed gas stream that comprises methane, ethane, propane, and heavier hydrocarbons into a residue gas stream comprising the methane and the ethane and a natural gas liquids (NGL) stream comprising the propane and heavier hydrocarbons; compressing the residue gas stream to produce a hot and compressed residue gas stream; and heating a portion of the NGL stream with the hot and compressed residue gas stream.
 2. The method of claim 1, further comprising separating the NGL stream into a first portion and a second portion, and wherein heating the portion of the NGL stream comprises heating the second portion with the compressed residue gas stream.
 3. The method of claim 1, wherein heating the portion of the NGL stream comprises heating a heating oil with the hot and compressed residue gas stream to form a heated heating oil and heating the portion of the NGL stream with the heated heating oil.
 4. The method of claim 3, further comprising providing addition heat to the heating oil using an external energy input.
 5. The method of claim 1, wherein heating the portion of the NGL stream comprises directly exchanging heat between the hot and compressed residue gas stream and the portion of the NGL stream.
 6. The method of claim 1, further comprising expanding a first portion of the feed gas stream prior to separating the feed gas stream.
 7. The method of claim 1, wherein separating the feed gas stream comprises cooling a second portion of the feed gas stream.
 8. The method of claim 1, wherein separating the feed gas stream comprises combining the first and second portions of the feed gas stream to form a combined gas stream and contacting the combined gas stream with a mass transfer contacting device.
 9. The method of claim 8, further comprising contacting the portion of the NGL stream with the mass transfer contacting device.
 10. The method of claim 1, further comprising air cooling the hot and compressed residue gas stream subsequent to heating the portion of the NGL stream with the hot and compressed residue gas stream.
 11. A method for separating hydrocarbons comprising the steps of: passing a feed gas stream to a distillation column, the feed gas stream comprising methane, ethane, and propane and heavier hydrocarbons; in the distillation column, separating the methane and the ethane from the propane and heavier hydrocarbons, thereby producing a residue gas stream comprising the methane and the ethane at an upper section of the distillation column and a natural gas liquids (NGL) stream comprising the propane and heavier hydrocarbons at a lower section of the distillation column; separating the NGL stream into a first portion and a second portion, withdrawing the first portion from the distillation column as a product NGL stream, heating the second portion in a reboiler of the distillation column, and returning the heated second portion from the reboiler to the distillation column; passing the residue gas stream to a compressor to produce a hot and compressed residue gas stream; and directing heat from the hot and compressed residue gas stream to the reboiler to perform the step of heating the second portion of the product NGL stream.
 12. The method of claim 11, wherein directing heat from the hot and compressed residue gas stream to the reboiler comprises heating a heating oil with the hot and compressed residue gas stream to form a heated heating oil and heating the second portion of the NGL stream with the heated heating oil.
 13. The method of claim 12, further comprising providing addition heat to the heating oil using an external energy input.
 14. The method of claim 11, wherein directing heat from the hot and compressed residue gas stream to the reboiler comprises directly exchanging heat between the hot and compressed residue gas stream and the second portion of the NGL stream.
 15. The method of claim 11, further comprising, prior to passing the feed gas stream to the distillation column, passing a first portion of the feed gas stream to an expander/compressor to expand and cool the first portion of the feed gas stream.
 16. The method of claim 15, further comprising, prior to passing the feed gas stream to the distillation column, passing a second portion of the feed gas stream to a heat exchanger to cool the second portion of the feed gas stream.
 17. The method of claim 16, further comprising exchanging heat between the residue gas stream with the second portion of the feed gas stream, prior to passing the residue gas stream to a compressor.
 18. The method of claim 17, further comprising combining the first and second portions of the feed gas stream prior to passing the feed gas stream to the distillation column.
 19. The method of claim 1, further comprising air cooling the hot and compressed residue gas stream subsequent to directing heat from the hot and compressed residue gas stream to the reboiler.
 20. A system for separating hydrocarbons comprising: a distillation column that a) receives a feed gas stream comprising methane, ethane, and propane and heavier hydrocarbons and b) separates the methane and the ethane from the propane and heavier hydrocarbons to produce a residue gas stream comprising the methane and the ethane at an upper section of the distillation column and a natural gas liquids (NGL) stream comprising the propane and heavier hydrocarbons at a lower section of the distillation column; a reboiler associated with the distillation column that a) receives a portion of the NGL stream from the distillation column, b) heats the portion of the NGL stream to form a heated NGL stream, and c) returns the heated portion of the NGL stream to the distillation column; a compressor that compresses the residue gas stream to produce a hot and compressed residue gas stream; and a heat exchange apparatus that directs heat from the hot and compressed residue gas stream to the reboiler to provide heat to the reboiler to accomplish the function (b) of heating the portion of the NGL stream. 